Loading...
HomeMy WebLinkAbout20230601Direct Aschenbrenner .pdf BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION OF IDAHO POWER COMPANY FOR AUTHORITY TO INCREASE ITS RATES AND CHARGES FOR ELECTRIC SERVICE IN THE STATE OF IDAHO AND FOR ASSOCIATED REGULATORY ACCOUNTING TREATMENT. ) ))) )) CASE NO. IPC-E-23-11 IDAHO POWER COMPANY DIRECT TESTIMONY OF CONNIE G. ASCHENBRENNER ASCHENBRENNER, DI 2 Idaho Power Company Q. Please state your name, business address, and 1 present position with Idaho Power Company (“Idaho Power” or 2 “Company”). 3 A. My name is Connie G. Aschenbrenner. My 4 business address is 1221 West Idaho Street, Boise, Idaho 5 83702. I am employed by Idaho Power as the Rate Design 6 Senior Manager in the Regulatory Affairs Department. 7 Q. Please describe your educational background. 8 A. In May of 2006, I received a Bachelor of 9 Business Administration degree in Finance from Boise State 10 University in Boise, Idaho. In December of 2011, I earned a 11 Master of Business Administration degree from Boise State 12 University. In addition, I have attended the electric 13 utility ratemaking course The Basics: Practical Regulatory 14 Training for the Electric Industry, a course offered 15 through New Mexico State University’s Center for Public 16 Utilities. 17 Q. Please describe your work experience with 18 Idaho Power. 19 A. In 2012, I was hired as a Regulatory Analyst 20 in the Company’s Regulatory Affairs Department. My primary 21 responsibilities included support of the Company’s 22 Commercial and Industrial customer class’s rate design and 23 general support of tariff rules and regulations. In my time 24 as a Regulatory Analyst, I also provided support for 25 ASCHENBRENNER, DI 3 Idaho Power Company Residential and Small General Service rate design, as well 1 as regulatory support associated with demand-side 2 management (“DSM”) activities. In 2017, I was promoted to 3 Rate Design Manager for Idaho Power, and in 2019 I was 4 promoted to my current role as Rate Design Senior Manager. 5 I am currently responsible for the management of the rate 6 design strategies of the Company, as well as oversight of 7 all tariff administration. In my current role, I am also 8 one of the Company representatives at its Energy Efficiency 9 Advisory Group (“EEAG”) meetings. 10 Q. What is the purpose of your testimony in this 11 matter? 12 A. In my testimony, I will describe generally how 13 customer rates are developed and the Company’s approach to 14 rate design strategy as well as the policy basis for the 15 rate design proposals being made in this case. I will also 16 describe the overall objectives I provided to the 17 Regulatory Consultants and Analysts for the development of 18 the Company’s proposed rate designs and general tariff 19 updates. I will also present an overview of the Company’s 20 approach to developing pricing for its on-site generation 21 customers, specifically considering interdependencies 22 between this case and Case No. IPC-E-23-14, which is 23 currently pending before the Idaho Public Utilities 24 Commission (“Commission”). Finally, I will describe the 25 ASCHENBRENNER, DI 4 Idaho Power Company approach the Company took to updating its tariff schedules 1 and rules to ensure the language in the tariff reflects 2 current business practices. 3 Q. Please provide a witness overview for the 4 Company’s CCOS, rate design, and general tariff revision 5 proposals. 6 A. Company Witness Mr. Paul Goralski will present 7 the Company’s recommendation as it relates to class cost-8 of-service (“CCOS”) in this case and will also present rate 9 design recommendations for the Company’s existing Special 10 Contract customers (Micron, Simplot – Pocatello, and INL) 11 as well as pending and prospective Special Contract 12 customers (Brisbie, Lamb Weston, and Simplot – Caldwell). 13 Mr. Goralski will also present the rate design proposal for 14 Schedule 20, Speculative High-Density Load as well as the 15 proposed Fixed Cost Adjustment rates and the corresponding 16 modifications to Schedule 54. 17 Company Witness Mr. Grant Anderson will explain the 18 proposed rate design and resulting prices for the 19 residential classes, including standard service (Schedule 20 1), time-of-use (“TOU”) (Schedule 5), and residential on-21 site generation (Schedule 6) and will explain the Company’s 22 Residential Price Modernization Plan. Mr. Anderson will 23 also present the rate design proposals for Small General 24 Service On-Site Generation (Schedule 8), Large General 25 ASCHENBRENNER, DI 5 Idaho Power Company Service – Primary and Transmission (Schedule 9P/T) and 1 Large Power customers (Schedule 19). 2 Company Witness Mr. Zack Thompson will present the 3 rate design proposals for Small General Service (Schedule 4 7), Large General Service – Secondary (Schedule 9S), 5 Agricultural Irrigation Service (Schedule 24), Dusk to Dawn 6 Customer Lighting (Schedule 15), Street Lighting Service 7 (Schedule 41), Traffic Control Signal Lighting Service 8 (Schedule 42), and Non-Metered General Service (Schedule 9 40). 10 Finally, Company Witness Mr. Riley Maloney will 11 present the recommendation for the Company’s Standby 12 Service schedules (Schedules 31 and 45) and Alternate 13 Distribution Service schedule (Schedule 46). Mr. Maloney 14 will also present several proposed modifications to the 15 Company’s tariff. 16 I. RATE DESIGN OVERVIEW AND OBJECTIVES 17 Q. How are customer rates developed? 18 A. After the Idaho jurisdictional revenue 19 requirement is determined, the Company develops a class 20 cost-of-service study (“CCOS Study”) whereby it allocates 21 the revenue requirement to each customer class based on 22 their specific utilization of the system. The methodology 23 for separating costs among classes consists of a three-step 24 process generally referred to as classification, 25 ASCHENBRENNER, DI 6 Idaho Power Company functionalization, and allocation. In all three steps, 1 recognition is given to the way in which the costs are 2 incurred by relating these costs to the way in which the 3 utility is operated to provide electrical service. Once 4 individual costs have been allocated to the various classes 5 of service, it is possible to total these costs as 6 allocated and arrive at a breakdown of functionalized and 7 classified unit costs which can be relied on to inform rate 8 design. 9 Q. Please describe the objectives underlying the 10 Company’s rate design strategy. 11 A. The Company’s primary rate design objective is 12 to establish rate structures and prices that will recover 13 the revenue requirement targets for each customer class. 14 Additionally, the Company seeks to design rates that assign 15 costs to those customers that cause the Company to incur 16 the costs, a principle known as “cost causation,” and to 17 incorporate price signals to encourage wise and efficient 18 use of energy. 19 Q. How can rate design influence customer 20 behavior? 21 A. The rate design itself – or structure – and 22 the prices set by these designs can impact the amount of 23 electricity customers consume and either encourage or 24 discourage usage at certain times. The Company believes 25 ASCHENBRENNER, DI 7 Idaho Power Company that rates should be designed in a manner such that changes 1 in a customer’s consumption (both the timing or quantity of 2 usage) will result in decreases or increases to the 3 customer’s bill that track with overall decreases or 4 increases in costs incurred by the utility to provide 5 service. 6 Q. How effective are the Company’s current rate 7 structures in achieving its rate design objectives? 8 A. Current rate structures fall short of 9 achieving the Company’s long-term objectives in a number of 10 key areas. A large portion of the fixed costs to serve 11 customers is collected through volumetric energy charges. 12 In other words, the rate structure does not align well with 13 how costs are incurred, and as a result, the price signals 14 sent to these customers are inconsistent with the nature of 15 the costs of providing electricity. Further, the rates 16 offer little incentive for customers to use electricity 17 cost-effectively. 18 Q. Why does the Company believe it is important 19 to align prices with the underlying cost structure? 20 A. Customers respond to price signals. If the 21 Company’s rate structures are not aligned with the 22 underlying cost drivers, customers do not have access to 23 information that will allow them to make decisions based on 24 the economics from their perspective or for the broader 25 ASCHENBRENNER, DI 8 Idaho Power Company utility system. This dynamic is increasingly important to 1 Idaho Power’s system. Over the last several years, 2 advancements in technology have influenced customer 3 adoption of several behind-the-meter energy solutions, 4 including energy efficiency, smart appliances, on-site 5 generation, and energy storage systems. The Company 6 believes that structuring rates in a manner that will more 7 equitably collect fixed costs, while also sending price 8 signals to promote efficiencies, is important to the long-9 term management of system costs. 10 In addition to sending the right price signal to 11 influence behavior, cost-informed rates help to limit cross 12 subsidies within a given class. 13 Q. Are there any other policy objectives to 14 consider regarding rate design? 15 A. Yes. There are several other important 16 ratemaking objectives the Commission has historically 17 relied upon when ultimately establishing rates. These 18 include evaluating customers’ ability to pay, 19 understandability of the rate structure and rates 20 themselves, and to what extent the rates provide some 21 stability for customers. While the Company believes each of 22 these objectives is important and should factor into an 23 ultimate decision, it also believes that the best starting 24 point for Commission deliberations is an economic one. 25 ASCHENBRENNER, DI 9 Idaho Power Company II. RATE DESIGN RECOMMENDATIONS 1 Q. Has the Company identified opportunities for 2 improving the current rate design applicable to its major 3 customer classes? 4 A. Yes. Generally, the Company is proposing to 5 adjust each of the billing components within its existing 6 structures to move incrementally closer to their cost-of-7 service, while targeting collection of the revenue assigned 8 to each class. Accordingly, I have directed each of the 9 Company witnesses who have prepared rate design 10 recommendations to prioritize movements in collection 11 towards cost-of-service, which includes moving away from 12 tiered rate designs and shifting fixed cost collection into 13 the appropriate charges, while balancing the magnitude of 14 those changes with the resulting customer impacts. Table 1 15 shows a summary of the requested rate design changes for 16 the Company’s existing service schedules and identifies the 17 Company witness who developed the proposed rates. 18 //19 ASCHENBRENNER, DI 10 Idaho Power Company Table 1 1 Summary of Existing Rate Designs & Proposed Modifications 2 Current Structure Proposed Modifications Witness Residential (Schedules 1 & 6) •Service Charge • 3 Inclining Block Tiers • collection through the Service Charge • Flatten the tiers Anderson Residential Time- of-Use (“TOU”) (Schedule 5) •Service Charge • Summer On & Off-Peak • Non-Summer Mid & Off- Peak • align with IRP-informed hours of highest risk • Introduce larger Small Commercial (Schedules 7 & 8) •Service Charge • 2 Inclining Block Tiers • collection through the Service Charge and flatten Anderson Large Commercial Secondary (Schedule 9S) •Service Charge • Two-Block Demand/BLC • 2 Declining Block Tiers • collection through the Service Charge • Replace Two-Block Demand/BLC and Declining Tiers with a seasonal, flat rate • Introduce an optional TOU Irrigation (Schedule 24) •Service Charge • In-Season Demand • Load-Factor Pricing • collection through the Service Charge • Replace Load-Factor Pricing with a flat energy Large Commercial Primary & Transmission (Schedules 9P/T) •Service Charge • Demand, BLC, and On- Peak Demand • TOU Energy Rates • elements with underlying cost drivers as informed by CCOS Large Power (Schedule 19) •Service Charge • Demand, BLC, and On- Peak Demand • TOU Energy Rates Better align existing elements with underlying cost drivers as informed by CCOS Special Contracts (Schedules 26, 29, 30, & 32) •Varied •Better align existing elements with underlying cost drivers as informed by ASCHENBRENNER, DI 11 Idaho Power Company Q. Please describe the Company’s general 1 goals/strategies for addressing the weaknesses in existing 2 rate designs in this case. 3 A. In this case, the Company intends to establish 4 rate structures that are more in line with cost causation, 5 while balancing customer understandability and bill impact. 6 Overall, the Company is seeking to implement changes that 7 will take a step towards correcting a long-standing 8 inequity within the residential class by implementing a 9 plan to establish better price signals within that class. 10 Further, the Company’s proposal will continue to better 11 align the commercial and irrigation rate designs with cost-12 causation, providing for more economic price signals to 13 those customer classes. 14 A. Eliminate Tiered Rate Design 15 Q. What rate classes currently rely on some form 16 of tiered rates? 17 A. Schedules 1, 6, 7, 8, 9S and 24 all rely on a 18 form of tiered rates. Currently, Idaho Power’s tiered rates 19 include inclining block rates, whereby the prices 20 associated with each defined block of energy usage is 21 higher than the proceeding block, and declining block 22 rates, whereby the prices associated with each block of 23 energy usage is lower than the proceeding block. 24 ASCHENBRENNER, DI 12 Idaho Power Company Inclining Block Rates 1 Q. What rate classes currently have an inclining-2 block tiered rate design? 3 A. Schedules 1, 6, 7, and 8. Schedules 1 and 6 4 rely on a three-tiered inclining block structure while 5 Schedules 7 and 8 rely on a two-tiered inclining block 6 structure. 7 Q. What is the purpose of an inclining-block 8 rate? 9 A. A primary goal of an inclining tiered 10 structure is to encourage conservation by charging a higher 11 rate as energy consumption increases over a billing period. 12 Once a threshold of energy consumption is exceeded within a 13 billing period, the rate becomes higher to send a price 14 signal intended to encourage efficiency and/or 15 conservation. Historically, the inclining block rate 16 structure has been used as a tool for encouraging customers 17 to use less energy. The theory underlying this concept is 18 that the first block covers some basic level of usage at a 19 lower rate to help keep the overall bill affordable for 20 customers and sequential blocks with higher rates make 21 incremental energy usage more expensive to encourage energy 22 efficiency. 23 Q. Are there downsides to this type of a rate 24 design? 25 ASCHENBRENNER, DI 13 Idaho Power Company A. Yes. The tiered rate structure has potential 1 to unfavorably impact bills of customers who reside in 2 older, less efficient homes, or those homes with all-3 electric heat. These customers may be unable to safely 4 reduce their energy beyond a certain threshold or may not 5 be able to efficiently reduce their energy usage in 6 response to the established price signals. The most 7 significant downside is that the tiered rate structure does 8 not reflect how costs are incurred throughout the billing 9 period and therefore does not send a price signal related 10 to the differing costs to produce or procure energy 11 throughout the billing period. 12 Proponents of inclining block rates believe they 13 provide customers with greater control over their electric 14 charges. However, it is important to note that high-end 15 energy use is often electric heating and cooling, and while 16 customers can elect to turn off or lower their heating 17 requirements to lower their bill, this could compromise 18 basic health and safety. The Company does not believe an 19 inclining block structure is the right way to promote 20 energy efficiency for residential customers over the long-21 term, and, as explained more fully below, proposes to 22 transition to a rate design that will better enable 23 efficiencies on its system. 24 ASCHENBRENNER, DI 14 Idaho Power Company In short, tiered rates are not cost-based and serve 1 to penalize higher usage customers. 2 Q. Why are tiered rates not cost-based? 3 A. There is no cost-based reason why after using 4 800 kilowatt hours (“kWh”) or 2,000 kWh in a billing period 5 the next kWh consumed by a customer should cost more. 6 Conversely, the timing of energy consumption, both 7 seasonally and during different hours, can affect the 8 utility’s cost of providing service to the customer. The 9 load factor or the effective utilization of kWh consumption 10 relative to peak kilowatt (“kW”) demand can also change the 11 average cost of providing energy. However, additional 12 overall usage in a customer’s billing period does not make 13 it incrementally more expensive for the utility to produce 14 the next kWh of electricity when both fixed and variable 15 costs are considered. 16 Q. Why do tiered rates unduly penalize customers? 17 A. Charging higher prices for greater usage in 18 each billing period generally causes large users to 19 subsidize smaller users. Under a tiered rate structure, 20 customers who heat their homes with natural gas benefit and 21 those who use electric heat are penalized. A household with 22 several people living under one roof will be more likely to 23 have usage in the higher second and third block rate than a 24 person living alone. Effectively, inclining block rates 25 ASCHENBRENNER, DI 15 Idaho Power Company unfairly reward some customers and penalize others, often 1 for reasons outside the customer’s control. For those 2 reasons, the Company is proposing to eliminate this type of 3 rate structure for its residential customers over time. 4 Q. Are there any other reasons why the Company 5 believes that eliminating tiers from Schedule 1 is 6 advantageous? 7 A. Yes. Eliminating tiers for Schedule 1 makes 8 the comparison to Schedule 5, which does not have tiers, 9 easier for customers to assess regarding the potential 10 benefits of time-variant pricing. 11 Additionally, moving away from an inclining block 12 tiered structure to a seasonally flat structure would 13 better position residential customers for future pricing 14 structure changes. For example, a change from a seasonal 15 flat rate to an introductory or mandatory TOU rate would 16 cause less customer confusion – whereas a change from the 17 existing inclining block structure to TOU rates may be more 18 volatile and cause a varying degree of bill impacts to 19 individual customers. 20 Declining Block Rates 21 Q. What rate classes currently have a declining -22 block tiered rate design? 23 A. Schedules 9S and 24. 24 ASCHENBRENNER, DI 16 Idaho Power Company Q. Please describe the details of the declining 1 block tiered rate that applies to Schedule 9S. 2 A. The Schedule 9S rate design includes a two-3 tier declining block energy charge and a two-block demand 4 and basic load capacity (“BLC”) charge. In this rate 5 design, the first block of kWh consumption is billed at a 6 higher rate than all other consumption. 7 Q. Is the Company proposing changes to the 8 Schedule 9S rate design? 9 A. Yes. Under the Schedule 9S rate design, the 10 higher first block energy charge is intended to collect 11 costs that are classified as demand and would otherwise be 12 collected through a demand charge. As described by Mr. 13 Thompson in this case, the Company is proposing to “unwind” 14 the declining block Schedule 9S rate design and replace it 15 with a rate structure more in line with other large general 16 service customers, containing a billing demand and BLC 17 applied to all kW and seasonal energy charges. 18 Q. Please explain the considerations in 19 evaluating the change to Schedule 9S. 20 A. The Schedule 9S rate design was initially 21 implemented in the 2005 general rate case1 primarily to ease 22 impacts on customer bills as a customer’s usage made them 23 1 In the Matter of the Application of Idaho Power Company for Authority to Increase its Base Rates and Charges for Electric Service in the State of Idaho, Case No. IPC-E-05-28, Order No. 30035 (May 12, 2006). ASCHENBRENNER, DI 17 Idaho Power Company ineligible for Schedule 7 service and where they instead 1 qualified for service under Schedule 9S. At that time, 2 customers were experiencing a “pain point” when they 3 transitioned back and forth between Schedule 7 and Schedule 4 9 due to the differences in the rate designs. Several 5 changes were made to the address that pain point, including 6 modifying the eligibility criteria so that once a customer 7 qualifies for Schedule 9 service, they will continue to 8 take service under that schedule. At the time, the Company 9 signaled that combining the Schedule 7 and Schedule 9S 10 class may be most appropriate in the long term. 11 Q. Did the Company consider providing additional 12 customer options to help improve understandability or 13 provide a price signal to promote system efficiency? 14 A. Yes. As more fully described below, the 15 Company is proposing to implement an optional TOU rate 16 structure where time-differentiated volumetric energy rates 17 would give a better price signal to prioritize the more 18 critical times when customers could shift load. It costs 19 more to serve load during summer and non-summer peak times 20 and an on-peak summer rate encourages more efficient use of 21 the system as well as fairly charging customers based on 22 their load profiles. 23 Q. Is the Company proposing to combine the small 24 and large general secondary rate classes in this case? 25 ASCHENBRENNER, DI 18 Idaho Power Company A. No. In this case, the Company is proposing to 1 slightly modify the Schedule 7 design, as more fully 2 described in the Direct Testimony of Mr. Thompson, to 3 collect more fixed costs through the Service Charge and 4 commensurately reduce the reliance on volumetric rates for 5 fixed cost collection. The Schedule 7 class has a 6 disproportionate number of small users (nearly 60 percent 7 of the class uses less than 300 kWh per month), and the 8 Company determined that, at this point, it would not 9 propose combining the classes. 10 However, in evaluating its proposed rates, the 11 Company did consider how Schedule 7 customers transitioning 12 onto Schedule 9 would be impacted, which in part influenced 13 the proposed level of collection through the Service Charge 14 for both Schedules 7 and 9S. 15 Q. What rate design currently applies to Schedule 16 24? 17 A. Schedule 24 relies on “load factor pricing” 18 which is like a declining block, where the price of the 19 first tier is higher than that of the second tier. The 20 first block charges irrigation customers a monthly rate per 21 kWh for the first 164 kWh per kW of demand, where the 22 second block charges customers a lower monthly energy rate 23 per kWh of all other energy use. 24 Q. Is this rate design cost based? 25 ASCHENBRENNER, DI 19 Idaho Power Company A. No. Like the Schedule 9S rate design, this 1 rate design collects costs otherwise classified as demand 2 through the first block; however, unlike the Schedule 9S 3 design, customers are charged for all units of billing 4 demand during the in-season time period. The Company has 5 found this rate design tends to be complex to explain to 6 customers. As a result, and as described in the Direct 7 Testimony of Mr. Thompson, the Company is proposing to move 8 the demand-classified costs out of the first tier and 9 collect those costs through the demand charge, which the 10 Company believes would be a more straightforward rate 11 design for Schedule 24 customers to understand. 12 B. Expanded Summer Season & TOU Rates 13 Q. Do the Company’s current rate structures 14 reflect the time-variant nature of electricity? 15 A. Only to an extent. The rate designs applicable 16 to most of the Company’s service schedules include a 17 seasonal component. Additionally, the large users, 18 Schedules 9 P/T and 19, have mandatory time-differentiated 19 energy charges. 20 Q. What is the Company’s view on seasonal rates? 21 A. The cost to provide service to customers 22 varies throughout different times of the year. For Idaho 23 Power’s system, it is generally more expensive to meet 24 customer energy requirements in the summer and seasonal 25 ASCHENBRENNER, DI 20 Idaho Power Company rates are an effective tool to promote reduced consumption 1 during those higher cost months. Acknowledging this, the 2 Company implemented seasonal rates for Schedules 1, 7, 9, 3 and 19 in its 2003 General Rate Case (“GRC”). Since that 4 time, the summer season for purposes of ratemaking has 5 remained unchanged – that is, for most customers, the 6 summer season is defined as June 1 through August 31. 7 Q. What is the Company’s proposed summer season 8 in this case and how did it develop that recommendation? 9 A. The Company is proposing to expand the summer 10 season by one month to include September. Over the last 11 several years, the Company’s Integrated Resource Plan 12 (“IRP”) has identified high-risk hours are more frequently 13 occurring later in the summer, often showing up in 14 September. Shifting to a four-month summer season better 15 aligns with current and future high-risk hours. 16 Q. What is the Company’s view on TOU rates? 17 A. TOU rates can be an effective way to send a 18 price signal to customers to encourage them to shift energy 19 usage to specific hours in the day that are less costly to 20 serve. This price signal can be effective to promote energy 21 efficiency and system efficiency rather than strictly a 22 conservation signal, as the tiered rates do. As more fully 23 described by Mr. Anderson and Mr. Thompson, the Company is 24 proposing to expand its TOU offerings for both residential 25 ASCHENBRENNER, DI 21 Idaho Power Company and commercial customers and to establish a basis for 1 potential opt-out or mandatory TOU rates for those classes. 2 Residential TOU 3 4 Q. Is the Company proposing to expand its TOU 5 offering for residential customers as part of this GRC? 6 A. Yes. The Company has had an optional TOU 7 offering in place for its residential customers since 2005; 8 however, only a small number of customers (currently less 9 than 1,000) opt to take that service from Idaho Power. The 10 Company is proposing to redesign its optional residential 11 TOU offering in a few ways: (1) modify and shorten the on-12 peak windows to align with the Company’s highest risk hours 13 as informed by the 2023 IRP and (2) introduce a larger 14 differential between on- and off-peak times. 15 Q. Please generally describe how the TOU offering 16 was designed. 17 A. First, the Company relied on the analysis 18 performed by the power supply planning team in preparation 19 of the 2023 IRP to determine which hours are currently 20 considered highest risk. These hours were used to inform 21 the summer and non-summer on- and off-peak price periods 22 utilized in the Schedule 5 rate design. I then directed Mr. 23 Anderson to rely on the results of that analysis to inform 24 his rate proposal. 25 ASCHENBRENNER, DI 22 Idaho Power Company Q. How is the Company proposing to set the 1 differentials between on-, mid-, and off-peak? 2 A. The Company’s approach varied slightly by 3 customer class. For Schedule 5 customers, I directed Mr. 4 Anderson to develop the offering in a manner that would be 5 most effective at promoting a response to the price signal. 6 Q. Please describe how system efficiencies may be 7 gained under this type of a rate structure. 8 A. TOU pricing (including Critical Peak Pricing) 9 was identified as having the potential to manage customer 10 demand in a recently completed Demand Response Potential 11 Study, which will be relied on in the 2023 IRP. For the 12 residential class, the total potential from TOU pricing 13 programs amounted to approximately 8 MW. To the extent 14 customers respond to this type of a rate design, the 15 Company may be able to delay building traditional supply-16 side resources. 17 Q. Did the Company consider making TOU a default 18 or mandatory rate offering for residential customers? 19 A. Yes, however, while the Company believes TOU 20 is a more efficient and effective way to send energy and 21 system efficiency price signals, it is aware that a change 22 in a single year — from the current tiered rate structure 23 to a mandatory or even a default TOU program — would be a 24 significant impact to many of its residential customers 25 ASCHENBRENNER, DI 23 Idaho Power Company that may be unfamiliar with this type of rate design, or 1 who are otherwise unable to respond to the price signal. 2 Based on these considerations, in this case, the 3 Company is proposing a three-year transition whereby it 4 will gradually increase the Service Charge while 5 eliminating the inclining block tier rates, which, at the 6 end of the transition period, will better position the 7 Company to consider proposing mandatory or default TOU for 8 all customers in the future. This will also provide the 9 Company an opportunity to evaluate the impacts and 10 effectiveness of the on-peak to off-peak price ratio of 11 4.0x proposed in this case. 12 Commercial and Industrial TOU 13 14 Q. Is the Company proposing to modify or expand 15 TOU for its commercial and industrial customers? 16 A. Yes. Schedules 19 and 9P/T already have TOU 17 rates in place. The Company is aware that many of its 18 Schedule 9S customers would like to take service under a 19 time-differentiated rate design as this type of a design 20 will better enable customers with discretionary load to 21 manage their energy bills. 22 Q. Why is the Company proposing only an optional 23 TOU service offering for Schedule 9S customers as opposed 24 to making it a mandatory service? 25 ASCHENBRENNER, DI 24 Idaho Power Company A. The Company is proposing the optional Schedule 1 9S TOU offering at this time to incentivize customers, who 2 have the ability, to shift load to off-peak periods by 3 sending cost-based price signals informed by the Company’s 4 high-risk hours identified in preparation of the 2023 IRP. 5 This encourages customers to use the system more 6 efficiently and economically based on both how the Company 7 incurs cost and the high-risk time periods. 8 For example, if a customer with electric vehicle 9 charging stations selected the TOU offering, they would be 10 encouraged to charge their vehicles during off-peak hours. 11 This would lessen the burden on the system during on-peak 12 time periods as well as save the customer money compared to 13 if they were on the standard service offering. 14 Q. How is the Company proposing to set the 15 differentials between on- and off-peak? 16 A. I directed both Mr. Anderson and Mr. Thompson 17 to develop a proposal to isolate both the variable and 18 fixed cost components of the volumetric charge and only 19 apply a differential to the energy classified portion of 20 the rate. By developing the rates this way and having the 21 fixed cost component of the volumetric rate remain constant 22 for all kWh within a given season, the principles of cost-23 causation are maintained. That is, when a customer shifts 24 ASCHENBRENNER, DI 25 Idaho Power Company usage to another time period, the underlying costs are 1 expected to increase or decrease commensurately. 2 C. Residential Price Modernization Plan 3 Q. Please explain the Company’s Residential Price 4 Modernization Plan. 5 A. As more fully described in the Direct 6 Testimony of Mr. Anderson, the Company is proposing a 7 three-year transition period to modify the structure of its 8 residential rates whereby it will increase the Service 9 Charge and lower the energy charges commensurately over 10 that period. 11 Q. Why is Idaho Power requesting to implement the 12 Residential Price Modernization Plan? 13 A. The current residential rate structure does 14 not align with Idaho Power’s embedded cost structure. 15 Providing electric service requires a significant amount of 16 capital infrastructure, which is largely a fixed cost once 17 infrastructure goes into service. The current residential 18 rate structure is comprised of the Service Charge, which is 19 a monthly fixed charge, and Energy Charges, which are 20 usage-based or volumetric charges. 21 The Service Charge does not cover the fixed costs 22 incurred by residential customers and those fixed costs are 23 instead recovered through the volumetric Energy Charges. As 24 I explained above, the Energy Charges in Schedule 1 are 25 ASCHENBRENNER, DI 26 Idaho Power Company also tiered, so that usage over a specific threshold in a 1 billing period are priced at a higher rate. 2 Q. What is the downside to this rate structure? 3 A. The Company’s current rate structure for 4 residential customers recovers a high proportion of fixed 5 costs through the volumetric Energy Charges instead of 6 through fixed charges. This relationship results in higher 7 energy use customers subsidizing lower energy use customers 8 and generally leads to customers believing the value of a 9 kWh of energy is much higher than it is. 10 Q. What costs does the Company propose are 11 reasonably recovered through the Service Charge? 12 A. The Company proposes to recover all costs 13 related to the distribution system and customer-related 14 costs like metering, billing, and customer service through 15 the Service Charge. It is appropriate to include these 16 costs in the fixed monthly charges that residential 17 customers pay because they represent the fixed costs to 18 deliver power over the distribution system and provide 19 customer service and billing functions. These costs are 20 fixed in nature and do not vary with changes in volumetric 21 energy usage. If a residential customer uses less energy, 22 the fixed costs of distribution facilities that have been 23 installed to serve that customer do not decrease. These 24 costs are therefore appropriately recovered through the 25 ASCHENBRENNER, DI 27 Idaho Power Company fixed Service Charge. The Company proposes to continue to 1 recover all other costs – fixed generation and transmission 2 costs as well as variable energy costs – through Energy 3 Charges. 4 Q. Will this structure remove the energy 5 efficiency price signal? 6 A. No. As I mentioned, the Company is proposing 7 to continue to collect fixed charges associated with 8 generation and transmission through seasonal energy 9 charges, which will continue to promote energy efficiency. 10 As shown in Tables 6 and 7 of the Direct Testimony of Mr. 11 Anderson, in the first year of the change, the energy rates 12 are higher than they currently are – by the end of the 13 transition plan, the energy charges remain seasonally 14 differentiated, ensuring an efficiency signal remains. 15 Q. Did the Company consider the impact this rate 16 design would have on low-income customers? 17 A. Yes. As discussed in greater detail in the 18 Direct Testimony of Mr. Anderson, the Company evaluated the 19 impact of this rate design on those customers in its 20 service area known to be eligible for income-qualified 21 energy assistance and found the proposed rate design would 22 not disproportionally impact those customers in a negative 23 way. In fact, at the end of the transition period, these 24 ASCHENBRENNER, DI 28 Idaho Power Company customers are more likely to see a savings when compared to 1 the residential customer class in total. 2 Q. Why is the Company proposing that these 3 changes occur over a three-year transition? 4 A. Essentially, the Company is mindful of the 5 impacts this type of a rate design will have on lower-usage 6 customers and with gradualism in mind, has proposed a 7 multi-year timeframe to moderate bill impacts on individual 8 customers. The three-year transition provides a mechanism 9 to make changes that better align rates with cost-of-10 service while also balancing how these changes affect some 11 customers. Mr. Anderson presents a bill impact analysis to 12 show the bill impact for customers once the plan is 13 implemented. 14 III. ON-SITE GENERATION 15 Q. Please summarize the Company’s request 16 presented in Case No. IPC-E-23-14. 17 A. On May 1, 2023, Idaho Power filed Case No. 18 IPC-E-23-14 (“ECR Case”).2 The Company filed the case in 19 response to Commission Order No. 35631 directing the 20 Company to file a new case to implement changes to its on-21 2 In the Matter of Idaho Power’s Application for Authority to Implement Changes to the Compensation Structure Applicable to Customer On-Site Generation Under Schedules 6, 8, and 84 and to Establish an Export Credit Rate Methodology, Case No. IPC-E-23-14 (filed May 1, 2023). ASCHENBRENNER, DI 29 Idaho Power Company site generation offering. Specifically, the Company 1 requested the Commission implement: (1) real-time net 2 billing with an avoided cost-based financial credit rate 3 for exported energy, (2) a methodology for determining 4 annual updates to the ECR, (3) a modified project 5 eligibility cap for commercial, industrial, and irrigation 6 (“CI&I”) customers, (4) related changes to the accounting 7 for and transferability of excess net energy financial 8 credits, and (5) updated tariff schedules necessary to 9 administer the modified on-site generation offering. 10 Q. Are there any interdependencies between the 11 General Rate Case and Case No. IPC-E-23-14? 12 A. Yes. The Company is addressing a variety of 13 issues related to Idaho Power’s on-site generation offering 14 in the ECR Case. However, because a GRC is an appropriate 15 venue to address CCOS and rate design, the Company did not 16 present any recommendations related to those items in Case 17 No. IPC-E-23-14. Rather, those topics have been addressed 18 within this case. Further, the Company believes it is 19 appropriate to address transitional considerations in the 20 context of rates and rate design within this docket as this 21 GRC is the first opportunity to evaluate how closely 22 revenue collection for the on-site generation customers 23 aligns with the allocation of costs to those classes. 24 ASCHENBRENNER, DI 30 Idaho Power Company Q. How did the Company approach CCOS cost-1 allocation for on-site generation customers? 2 A. I requested load research statistics be 3 developed based on on-site generation customers’ 4 utilization of the system. I then directed Mr. Goralski to 5 rely on those statistics to complete cost-allocation to the 6 on-site generation customers. This required relying on only 7 a “delivered channel” of meter data for allocating 8 generation, transmission, and energy related costs and 9 looking at the maximum of both the “delivered channel” and 10 “received channel” in determining the allocation of 11 distribution plant. This is consistent with the real-time 12 measurement interval presented in the ECR Case. 13 Q. Did legacy status3 impact cost allocation? 14 A. No; the Company evaluated the cost to serve 15 all customers with on-site generation in the same manner, 16 regardless of legacy status. The type of compensation 17 structure applied to the billings for customers has no 18 bearing on measuring those customer’s utilization of the 19 system. In all cases, for all classes, the Company assessed 20 the classes’ energy and demand requirements in determining 21 cost allocation. The approach I described ensures on-site 22 3 The Company uses the term legacy to refer to those systems that the Commission has previously determined would continue to take NEM, under certain conditions, for a period of 25 years (also known as “grandfathered” systems). ASCHENBRENNER, DI 31 Idaho Power Company generation customers are not treated any different than 1 standard service customers. 2 Q. Are there any other areas related to on-site 3 generation that are being addressed in this docket rather 4 than in the ECR Case? 5 A. Yes. In Order No. 34046, the Commission 6 directed Idaho Power to evaluate rate design and 7 specifically “transitional rates.” In the ECR Case, the 8 Company proposed that any transitional considerations be 9 better addressed when evaluating the reasonableness of 10 pricing proposals in the GRC versus the ECR Case, which is 11 focused on the modification of the measurement interval 12 applied to excess net energy and the valuation of that 13 excess energy. 14 Q. What were the results of the CCOS for 15 Schedules 6 and 8? 16 A. The study, prior to the cap and spread process 17 described by Mr. Goralski, showed that the Schedule 6 and 8 18 classes should receive a 52 percent and 111 percent 19 increase, respectively, in their class revenue requirement. 20 These results demonstrate a large revenue deficiency for 21 Schedules 6 and 8 under current rates, relative to other 22 classes. 23 Q. Is the Company proposing rates for those 24 classes to target the CCOS revenue requirement? 25 ASCHENBRENNER, DI 32 Idaho Power Company A. No. The Company believes it is reasonable to 1 consider transitioning Schedule 6 and 8 customers to cost 2 of service over a period of time. If the Company were to 3 rely on the underlying CCOS as a basis for revenue 4 allocation, those customers would experience relatively 5 large increases in this case. 6 Q. How did the Company establish revenue targets 7 for Schedules 6 and 8 for rate design purposes? 8 A. As a mitigation measure, the Company combined 9 the Schedule 6 class with all residential customers (and 10 Schedule 8 with all small general service customers) to 11 complete both the cap and spread and the rate design 12 process. That is, in this case Idaho Power proposes that 13 on-site generation customers take service from Idaho Power 14 under the same rates that all standard service customers 15 pay. 16 Q. Will this result in a subsidy? 17 A. Yes. Any class whose assigned revenue 18 requirement is more than the amount authorized will be 19 subsidized by other customer classes. 20 Q. Does the Company believe its proposal results 21 provides a reasonable and fair transition period for 22 Schedule 6 and 8 customers? 23 A. Yes. The Company believes this approach 24 results in a reasonable transition period for on-site 25 ASCHENBRENNER, DI 33 Idaho Power Company generation customers and aligns with prior Commission 1 orders where the Commission has directed the Company to 2 evaluate transitional considerations as it proposes changes 3 that will impact on-site generation customers. 4 Q. How will Schedule 6 customers be impacted by 5 the Residential Price Modernization Plan? 6 A. Schedule 6 customers were included in the 7 determination of the revenue neutral rates developed as 8 part of the Residential Price Modernization Plan. It is 9 important to note that even at the end of the three-year 10 plan, Schedule 6 customers will still be contributing well 11 below their cost to serve. Idaho Power is not recommending 12 future changes be approved as part of this case, rather, 13 the Company will evaluate further rate design 14 considerations for on-site generation customers, as may be 15 necessary, in future rate proceedings. 16 IV. TARIFF ADMINISTRATION 17 Q. Is the Company proposing changes to its tariff 18 as part of this case? 19 A. Yes. The Company is requesting several 20 administrative and housekeeping edits to many of the rules 21 and schedules contained within its tariff. Additionally, I 22 directed Mr. Maloney to work with field and customer-facing 23 representatives to develop recommendations for updates and 24 additions necessary to administer the tariff in a manner 25 ASCHENBRENNER, DI 34 Idaho Power Company that ensures equitable treatment and is transparent to 1 customers. 2 Attachment Nos. 1 and 2 to the application contains 3 the legislative and clean versions of the requested tariff. 4 V. CONCLUSION 5 Q. Does this conclude your direct testimony in 6 this case? 7 A. Yes, it does. 8 //9 ASCHENBRENNER, DI 35 Idaho Power Company DECLARATION OF CONNIE G. ASCHENBRENNER 1 I, Connie G. Aschenbrenner, declare under penalty of 2 perjury under the laws of the state of Idaho: 3 1. My name is Connie G. Aschenbrenner. I am 4 employed by Idaho Power Company as the Senior Manager of 5 Rate Design in the Regulatory Affairs Department. 6 2. On behalf of Idaho Power, I present this 7 pre-filed direct testimony in this matter. 8 3. To the best of my knowledge, my pre-filed 9 direct testimony and exhibits are true and accurate. 10 I hereby declare that the above statement is true to 11 the best of my knowledge and belief, and that I understand 12 it is made for use as evidence before the Idaho Public 13 Utilities Commission and is subject to penalty for perjury. 14 SIGNED this 1st day of June 2023, at Boise, Idaho. 15 16 Signed: _________________________ 17 CONNIE G. ASCHENBRENNER 18 19 20 21 22 23 24 25